During the drilling, completion and maintenance of an oil well, personnel routinely insert and/or extract devices such as tubing, tubes, pipes, rods, hollow cylinders, casing, conduit, collars, and duct into the well. For example, a service crew may use a workover rig or service rig to extract a string of tubing and sucker rods from a well that has been producing petroleum. The crew may inspect the extracted tubing and evaluate whether one or more sections of that tubing should be replaced due to physical wear, thinning of the tubing wall, chemical attack, pitting, or other defect. The crew typically replaces sections that exhibit an unacceptable level of wear and makes note of other sections that are beginning to show wear and may need replacement at a subsequent service call.
As an alternative to manually inspecting tubing, the service crew may deploy an instrument to evaluate the tubing as the tubing is extracted from the well and/or inserted into the well. The scanning instrument typically remains stationary at the wellhead, and the workover rig moves the tubing through the instrument's measurement zone. This instrument may be called a “tube scanner”.
The tube scanner typically measures pitting and wall thickness and can identify cracks in the tubing wall. Radiation, field strength (electrical, electromagnetic, or magnetic), and/or fluid pressure differential may interrogate the tubing to evaluate these wear parameters. The tube scanner typically produces a raw analog signal and outputs a sampled or digital version of that analog signal.
In other words, the tube scanner typically stimulates a section of the tubing using a field, radiation, or pressure and detects the tubing's interaction with or response to the stimulus. An element, such as a transducer, converts the response into an analog electrical signal. For example, the tube scanner may create a magnetic field into which the tubing is disposed, and the transducer may detect changes or perturbations in the field resulting from the presence of the tubing and any anomalies of that tubing.
The analog electrical signal output by the transducer can have an arbitrary or essentially unlimited number of states or measurement possibilities. That is, rather than having two discrete or binary levels, typical transducers produce signals that can assume any of numerous levels or values. As the tubing passes through the measurement filed of the instrument, the analog transducer signal varies in response to variations and anomalies in the wall of the moving tubing.
The tube scanner also typically includes a system, such as an analog-to-digital converter (“ADC”), that converts the analog transducer signal into one or more digital signals suited for reception and display by a computer. These digital signals typically provide a “snapshot” of the transducer signal. Thus, the ADC typically outputs a number, or set of a numbers, that represents or describes the analog transducer signal at a certain instant in time. Because the analog transducer signal describes the section of tubing that is in the tube scanner's measurement zone, the digital signal is effectively a sample or a snapshot of a parameter-of-interest of that tubing section.
The signals generated by the tube scanner may fluctuate or drift over time. Vibrations or mechanical shocks that occur during transportation of the instrument may slightly alter the performance of the tube scanner. Thermal variance, power fluctuations, or vibrations during the operation of the tube scanner may cause drift or noise in the readings output by the tube scanner. These fluctuation, drift, and noise components of the signals output from the tube scanner may lead to inconsistencies of the type that would result in two different tube scanner outputs from scanning the same pipe at two different times. Such inconsistencies are undesirable when the tube scanner outputs are used for evaluating the wear and wear patterns of the tubing and determining if particular sections of tubing should be retained for reuse or otherwise discarded.
To address these representative deficiencies in the art, an improved capability for calibrating the tube scanner is needed. A need also exists for a capability of an oilfield service crew to calibrate the tube scanner in the field. A further need exists for a capability to use one or more post-operational calibrations to correct, validate, or flag the data scanned during the operation of the tube scanner.